CNOOC Turns On the Taps at Two Bohai Sea Fields Production has begun at CNOOC Limited’s Luda 6-2 and Bozhong 26-3 oil field expansion in the Bohai Sea. Luda 6-2 is flowing ahead of schedule, utilizing existing processing facilities of the Suizhong 36-1 oil field. The project has built a new central platform. A total of 38 development wells are planned, including 29 production wells, eight water-injection wells, and one development-and-appraisal well. The project is expected to reach peak production of around 10,000 B/D in 2022. The Bozhong 26-3 oilfield expansion project has also come online. In addition to fully utilizing existing processing facilities, new unmanned wellhead and power platforms were built for the project. A total of eight development wells are planned, including five production wells, two water-injection wells, and one development-and-appraisal well. The project is expected to reach peak production of 2,670 B/D in 2021. CNOOC Limited holds 100% interest in both projects. PPL Awarded Abu Dhabi Offshore Exploration Block A consortium of four Pakistani companies led by Pakistan Petroleum Limited (PPL) was awarded the exploration rights for Offshore Block 5 in Abu Dhabi’s second competitive block bid round. The award marks the first Pakistani company investment in and planned exploration for oil and gas in an Abu Dhabi concession as well as the first partnership between the Abu Dhabi National Oil Company (ADNOC) and Pakistani energy companies. Other companies in the consortium include Mari Petroleum Company Limited, Oil and Gas Development Company Limited, and Government Holdings (Private) Limited. Under the terms of the agreement, the consortium will hold a 100% stake in the exploration phase, investing up to $304.7 million toward exploration and appraisal drilling, including a participation fee, to explore for and appraise oil and gas opportunities in the block that covers an offshore area of 6223 km 2 and is located 100 km northeast of Abu Dhabi. “The PPL-led consortium is delighted to be selected for the concession award of Abu Dhabi’s Offshore Block 5,” said Moin Raza Khan, managing director and chief executive of PPL. “This award is not only a watershed moment for Pakistan and the Emirate of Abu Dhabi towards bilateral energy cooperation and economic links, but also offers an opportunity to strengthen strategic cooperation with ADNOC to share technical know-how and expertise.” Following a successful commercial discovery during the exploration phase, the consortium will have a production concession to develop and produce the discoveries. ADNOC has the option to hold a 60% stake in the production phase, which is 35 years from the commencement of the exploration phase. The block offers the potential to create significant in-country value for the UAE over the lifetime of the concession. In addition to drilling exploration and appraisal wells, the exploration phase will see the consortium leverage and contribute financially and technically to ADNOC’s mega seismic survey, which is acquiring 3D seismic data within the block area. The data already acquired over a large part of the block, combined with its proximity to existing oil and gas fields, suggest the concession area has promising potential. Hess Exits Denmark Upstream Hess Corporation has completed the previously announced sale of its subsidiary Hess Denmark ApS, which holds a 61.5% interest in the South Arne Field, to Ineos E&P AS for a total consideration of $150 million. “The sale of our Denmark asset enables us to further focus our portfolio and strengthen our cash and liquidity position,” said John Hess, chief executive of Hess. “Proceeds will be used to fund our world-class investment opportunity in Guyana.” The transaction was effective 1 January 2021. Beacon Offshore Secures Drillship for Shenandoah Work Beacon Offshore awarded Transocean a $252-million contract for use of its newbuild ultradeepwater drillship Deepwater Atlas to work in the Shenandoah field in the US Gulf of Mexico (GOM). The deal also includes a $30-million mobilization fee from Southeast Asia to the GOM. The Shenandoah program comprises two phases. Once delivered from the shipyard, the Deepwater Atlas is expected to begin operations in Q3 2022, initially using dual blowout preventers (BOP) rated to 15,000 psi. The duration of the drilling program is approximately 255 days and should result in $80 million in contract drilling revenue. Upon completion of initial drilling, a 20,000-psi BOP will be installed on the rig, making it Transocean’s second asset with a 20,000-psi-rated well-control system. The BOP installation and commissioning is expected to last 45 to 60 days, contributing $17 million in revenue. Following the 20,000-psi BOP installation, the Deepwater Atlas will begin the well completion program. The approximate duration of this phase is 275 days and should contribute $125 million in contract drilling revenue. Gambia Block Back on the Market The A1 block offshore Gambia is available for licensing again following a $29.3-million settlement with BP for failing to meet its drilling obligations there, according to the Gambian government. The oil major failed to drill a well before the initial exploration period expired on 29 July. “The A1 Block will revert to the government, free of all encumbrances,” the government statement said. “With BP’s exit, the A1 Block will now be on the market for licensing.” BP was awarded the block’s exploration rights in 2019. Brazil’s 3R Petroleum Negotiating Potiguar Purchase Petrobras is in talks with 3R Petroleum to sell a group of assets in the Potiguar basin for more than $1 billion. In a recent securities filing, Petrobras revealed that 3R presented the best offer in public bidding for the assets in the northeastern state of Rio Grande do Norte, known collectively as Polo Potiguar. The assets include 23,000 B/D of onshore and shallow-water oil production, according to 2020 bidding documents. It also includes the Potiguar Clara Camarao Refinery, which has installed capacity of 39,600 B/D. For 3R, the acquisition would more than double the company’s oil production and launch it into the top tier of Brazil’s independent producers, along with Enauta Participacoes and PetroRio. A successful sale would eliminate a noncore asset for Petrobras in a bid to reduce debt and focus on deepwater oil production. Petrobras Spuds Aram Block Wildcat Petrobras has started drilling a wildcat well in the Aram block of the pre-salt of the Santos Basin using Constellation drillship Brava Star, according to the National Petroleum Agency (ANP). The Aram block is operated by Petrobras (80%) in partnership with CNODC, a unit of China National Petroleum Corp. (20%). The two com­panies purchased the area in the only bid of the 6th Pre-­Salt Round in 2019. They paid $1.24 billion in signature bonuses and the minimum allowed profit oil of 29.96%. Drilling at Aram began on 24 August. With the new Petrobras well, Brazil returned to record levels in exploratory activity seen only in the pre­-pandemic period. In all, five wells were drilled in the country during August—the highest number in a single month since May 2019. DNO Begins Drilling at Gomez DNO has kicked off an exploration well at its Gomez prospect on PL006C license offshore Norway. The probe will be drilled to a depth of around 3300 m below sea level, targeting Paleocene-­age formations. DNO Norge AS holds a 65% operated interest in the license; Aker BP holds the balance. Aker BP originally had a 15% interest but recently acquired another 20% interest in PL006C from DNO under a swap agreement in which DNO picked up a 25% participating interest in PL1085 (Tanumåsen) and increased its share from 20 to 30% in PL906 (Mugnetind). The swap, pending government approval, will diversify Aker’s position in the southern North Sea. The Gomez well is being drilled using the Borgland Dolphin . The well is expected to take 45 days. Pre­drill reserve estimates range from 26 to 80 million BOE. The well is close to existing infrastructure, including the Tor and Ekofisk complexes. The Gomez well is one of three exploration wells scheduled this year. The first, Røver Nord (DNO 20%), resulted in what is likely a commercial discovery. Following Gomez, Mugnetind is expected to spud in Q4 2021. Petrobras Starts Production of FPSO Carioca in Sépia Field Petrobras began producing oil and natural gas from FPSO Carioca , the first platform in Sépia field, in the Santos Basin pre­salt. The FPSO is located approximately 200 km off the coast of Rio de Janeiro, in water depths of 2200 m. The FPSO, chartered from Modec, has the capacity to process up to 180,000 B/D and to compress up to 6 million m 3 of natural gas. Seven producing wells and four injection wells will be hooked into the FPSO. The oil production will be transported by offloading vessels, while the gas production will be moved through the pre­salt gas pipeline routes. The project also has a system to remove CO 2 from the gas produced and reinject it into the reservoir, reducing the release of carbon dioxide into the atmosphere and improving oil recovery. The Sépia shared reservoir comprises the Sépia and Sépia Leste fields, located in the Transfer of Rights and Concession (BM­S­24) areas, respectively, and operated by Petrobras (97.6%) in partnership with Petrogal Brasil (2.4%).

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30403, “Sand Production Management While Increasing Oil Production of a Gravel-Packed Well Equipped With Rate-Controlled-Production Autonomous Inflow-Control Devices in a Thin Heavy-Oil Reservoir Offshore China,” by Shuquan Xiong, Fan Li, and Congda Wei, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. A 2018 infill development campaign for a horizontal well offshore China targeted improved production through the installation of autonomous inflow-control devices (AICDs). However, because the well requires gravel packing to manage the sand, the integration of AICDs and the gravel pack was an issue. An integrated work flow was followed to deliver the AICD application successfully in an offshore heavy-oil reservoir with major uncertainties in remaining oil thickness and water/oil contacts. AICD completions ensured balanced contribution from all reservoir sections and limited water production significantly while the gravel pack kept the valves safe from the effects of sand. Field Description The field is a low-amplitude fault anticline oil field developed on the basement uplift. The structure is relatively gentle (Fig. 1). The reservoir lithology is mainly feldspathic quartz sandstone, with an average porosity of 22%, an average permeability of 397 md, a reservoir pressure coefficient of 1, an oil density of 0.92 g/cm 3 , and crude oil viscosity of 150 cp. The current methodology for gravel packing with ICDs/AICDs in the well uses a multiple alpha-wave technique whereby at least one conventional standalone screen joint is deployed at the toe of the well to provide a return path during the buildup of the alpha wave. The flow rate is reduced progressively to maximize the dune weight until screenout is observed. Once the gravel-packing operation is complete, the standalone-screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack to be achieved and will allow more gravel to build up around the zonal isolation packers. This methodology is most applicable in unconsolidated sands with high net-to-gross reservoirs where borehole collapse will occur early in well life. One technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint. However, in long lateral wellbores, this may be prohibitively expensive and requires multiple manual manipulations as the wash pipe is retrieved. The use of a temporary bypass valve is recommended to enable standard gravel-packing operations to be performed with ICDs without significant additional cost, complexity, or compromise. The dissolvable material is used with a valve located within the ICD/AICD housing to provide a high-flow-area path from the annulus to the tubing during completion operations.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa 18–22 April. The paper has not been peer reviewed. Carbon dioxide (CO 2 ) storage through CO 2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO 2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO 2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO 2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO 2 storage. Co-optimization of oil production and CO 2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO 2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO 2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO 2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO 2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO 2 injection and oil-production controls that maximize NPV in a CO 2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO 2 storage and oil-recovery approach was compared with that of the maximization of only-CO 2 -storage and only-oil-recovery approaches.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30277, “Twelve-Year Field Applications of Offshore Heavy Oil Polymerflooding From Continuous Injection to Alternating Injection of Polymer and Water,” by Guangming Pan, Lei Zhang, and Jianting Huang, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2-6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Polymerflooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa · s. The authors of the complete paper verify that alternating injection of polymer and water in the Bohai Bay of China proved effective and economical for heavy oil fields, even offshore. This polymerflooding pilot of initially continuous, and then alternating, injection can provide a useful technical reference for similar reservoirs. Introduction Heavy oil reserves are abundant in the Bohai oil field of China. The development of the field has proved that the field with lower viscosity (less than 350 mPa · s) can be developed effectively by water-flooding, while the unconventional heavy oil reservoir with high viscosity has not formed a mature development mode. To better use interwell reserves, a pilot polymerflooding test has been conducted in the NN field since 2008. The cumulative production of nine wells in the surrounding area reached 10.80×10 4 m 3 , which confirmed that polymer fluid injection had a good displacement effect on unconventional high-viscosity crude oil. However, with the extension of continuous injection time, the pilot test area faced various problems. In order to explore the applicability of polymerflooding technology used in offshore unconventional heavy oil fields, the polymer-injection mode was studied on the basis of laboratory experimental data and field practice, and the polymer/water alternating injection mode was analyzed. Experimental Continuous Polymerflooding. Experimental Equipment and Materials. The experimental device is composed of a driving system, an experimental model, a pressure-measurement system, a produced-liquid-collection system, and a temperature-control system. According to the distribution of reservoir physical properties in the NN field, a parallel double-tube displacement experiment with a permeability ratio of 5 was designed. The experimental cores are artificial, with a tube length of 30 cm and an inner diameter of 2.54 cm. The low-permeability tube has 1624×10 -3 µm 2 permeability, and the high-permeability tube has 8488×10 -3 µm 2 permeability. The experimental temperature is 55°C, which is consistent with the formation temperature of the NN field. The polymer is partially hydrolyzed polyacrylamide. Experimental Procedure. The experimental process includes vacuum pumping, saturating formation water, obtaining core pore volume, saturating simulated oil, calculating oil saturation water drive to a specified water cut, continuously injecting polymer solution, and measuring data. The experimental injection rate is 0.2 mL/min, and the multiple of injected pore volumes (PV) is 0.6 PV. The NN field has weak edge water, and the water cut of the well group was 60 to 90% when polymerflooding was performed. Therefore, the design scheme mainly includes waterflooding and polymerflooding stages. The polymer- injection concentration was 3000 mg/L, and the injection mode is continuous, consistent with the field test.

In the Bakken-Three Forks play of the Williston Basin, many oil wells that once produced some water have become water wells that produce some oil, as average oil production has flatlined while water production continues to increase. A complex interplay of stepping out beyond the core to where water saturations are higher, upsizing completions, tighter spacing, and dealing with greater parent-child effects and potential changes in relative permeability is significantly increasing volumes of produced water. Similar situations have been occurring in other basins. This is a serious threat for the US unconventional oil and gas industry, for which produced water has become a $34-billion industry and exposes operators to numerous operational, environmental, and economic risks. Software developers are beginning to adapt advanced machine-learning (ML) methods that have proved successful in forecasting oil production and upgrading them with aspects of game theory to make quick and accurate work of understanding and predicting water production in unconventional plays. Novi Labs (Novi), an Austin-based software company focusing on unconventional shale, has developed a solution that is being applied successfully in the Williston Basin to help disentangle the complex interactions of larger completion designs, changing geology, and tighter spacing that contribute to increased water production. According to the firm’s model, fluid per foot ranks as the most important input variable for increasing water production, ranking above proppant per foot and geologic parameters. Ted Cross, technical advisor at Novi and former senior geologist with Conoco Phillips, presented a paper that discussed the produced water challenge at the 2020 Unconventional Resources Technology Conference (URTeC). “How often does an engineer dash off a simple water forecast, doing something like applying a flat water-to-oil ratio to their water prediction?” Cross asked rhetorically. In unconventional oil fields, water forecasting and pre-drill water predictions have not received attention commensurate with their economic importance. “Quick is still common,” he said. Operators, regulators, and water-disposal companies often rely on simplistic water-cut ratios or basin-level extrapolations that ignore the complex interplay of geology, completions, and spacing decisions on water production. “They are starting to realize and incorporate the fact that water-to-oil ratios will evolve over a well’s life, usually increasing. But the critical thing is that the time they spend on water prediction is a tiny fraction of what they spend on oil, and the methods are less sophisticated and developed,” Cross said. Part of the reason, he explained, is that in the early development of the Eagle Ford, Permian, and some core parts of the Williston, either the original wells didn’t produce large volumes of water or the existing infrastructure around conventional plays was sufficient to handle it. But with field evolution and changing completion designs, water has become a critical issue.

Increasing sensitivity to oil price fluctuation requires operators to reduce costs of operation. A key component is collaborative management by operators and suppliers to reduce cost over the full life cycle of the operation. Much of the focus is on the equipment-purchasing strategy; nonetheless, effective technology such as an autonomous inflow control valve could also benefit the operating expenditure (OPEX) savings by enhancing oil recovery and reducing processing costs of excessive unwanted water and gas in surface facilities. OPEX comprises labor, chemicals, consumables, infrastructure maintenance, transportation, disposal, and other utilities. Capital expenditure (CAPEX) may also be reduced for long-term projects, which generally comprise infrastructure such as pipelines, pumps, disposal wells, ponds/storage treatment facilities, and other associated utilities infrastructure. The average cost for handling produced water starts from about $1.50/bbl, depending on the geographical location of the operation. Such costs may justify an assessment of an autonomous inflow control valve (AICV) to reduce unwanted water and gas to achieve OPEX savings. Horizontal wells are a proven option to maximize reservoir contact in certain situations. A challenge is often early water breakthrough in less than 6 months from starting production, and then progressively producing very-high water cuts, often 95%, for long periods of times thereafter. Inflow control device (ICD) technology has demonstrated potential in improving recovery in horizontal oil wells by delaying the gas and/or water breakthrough. However, ICDs cannot restrict water effluents once breakthrough occurs. A new generation of inflow control technology known as an AICV can balance the production flow and choke and shut the water-effluent zones once breakthrough occurs. Basis of Design The design is based on the Hagen-Poiseuille equation and Bernoulli’s principle. It uses the difference in fluid-flow behavior in the laminar- and the turbulent-flow restrictor to differentiate the pressure drop using the mobility ratio between oil, water, and gas. Light-viscosity fluids such as water and gas have high mobility and allow the AICV to detect the mobility difference, then choke and shut the main inflow area in the valve autonomously. Fig. 1 illustrates the construction of the valve in open positions, showing the direction of flow with arrows and the P1, P2, and P3 pressure locations. The inlet pressure is represented by P1: 2-5% of the main flow will move through the laminar-flow element (LFE) that will reduce the pressure to P2. Further pressure reduction occurs in the turbulent-flow element (TFE) to P3 as the tubing pressure. The differential pressure in LFE reacts to the piston’s effective area, resulting in a force balance around the piston to control the valve’s function (e.g., to open, choke, or close the main flow).

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195311, “Prescriptive Analytics for Completion Optimization in Unconventional Resources,” by Mehrdad Gharib Shirangi, SPE, Yagna Oruganti, and Thomas Wilson, Baker Hughes, et al., prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. This paper discusses a prescriptive analytics framework to optimize completions in the Permian Basin. The methodology involves data processing, ingestion into databases, and data cleansing; application of automated machine learning (AutoML) to generate an accurate machine-learning model; and numerical optimization of decision parameters to minimize an economic objective. Constructing a Pareto front enabled decision makers to select a strategy that minimized cost without sacrificing too much of the initial 12-month oil production. Overview A typical way to assess the performance of an oil well is to compute the total cost per barrel of oil produced at ultimate recovery. However, in cash-constrained operating environments, including many unconventional plays, other measures, such as $/bbl of oil produced in the first year, may also be used. Because of the intensive nature of running detailed physics-based models to optimize decision parameters related to wellbore placement and well completion, a pure simulation-based optimization strategy typically is not feasible. The complete paper describes a data-driven machine-learning model that was selected to predict the oil production profile of a new well in an unconventional play because of its efficiency and its ability to directly learn from abundant historical data. Data analytics are typically applied in three phases: Descriptive analytics, which makes sense of data Predictive analytics, which helps build an accurate machine-learning model to forecast a performance measure or an output on the basis of input parameters Prescriptive analytics, which helps to develop recommendations to improve performance Input parameters to the machine-learning model presented in the complete paper included system parameters (e.g., well location and trajectory, existence and type of artificial lift) and decision parameters (e.g., number of stages, amount of stimulation material). The authors used an optimization algorithm to explore systematically the space of decision parameters. Training data included drilling, completion, and production data from previous wells in the same formation. Initial input features were extracted and prepared on the basis of domain expertise. The AutoML process searched automatically among various machine-learning algorithms (e.g., neural networks, random forest) to find the best algorithm and the best associated hyper-parameters. A multiobjective optimization process was implemented to optimize the 12-month oil production ( Q oil ) and the completion cost divided by Q oil simultaneously. The methodology was applied to a real case in the Permian Basin, in collaboration with Diamondback Energy. The results demonstrated that the two objectives were conflicting. The construction of the Pareto front, which showed a set of optimal solutions, provided a visual tradeoff for decision makers and enabled them to select a strategy that minimized cost without sacrificing much of the initial 12-month oil production. The predictive model was then used to optimize the completion design of new wells to either maximize the cumulative oil produced, or minimize the completion cost per barrel of oil produced, in the first year.

At the end of a presentation on BP’s annual energy outlook last year, a petroleum engineering student from Greece asked, “Is a job as a petroleum engineer a good idea for the next decade?” Then BP CEO Bob Dudley responded by saying, “A job or training as an engineer of any kind is so important. There is going to be a huge need for that as you can see from Spencer’s outlook.” He was referring to the presentation made by Spencer Dale, group chief economist for BP, whose outlook showed oil demand likely growing until 2030, and remaining around 100 million B/D through 2050 while natural gas demand continues to rise. But how many oilfield engineers will be working in the decades ahead? A short JPT online story about that question struck a nerve with readers. It was one of the most-read stories online over the past year, with 21,000 views. The most downloaded SPE paper in 2019 on OnePetro was “The End of Petroleum Engineering as We Know It,” which predicted a significant change in what engineers do and the number needed to do it over the long term (SPE 194746). The idea for the paper came when 2016 SPE President Nathan Meehan said he began to have doubts about whether the assurances he was offering when asked that question by students were a realistic appraisal of the future. While he is happy to report that his son and a son-in-law both work in the oil business, he was not sure what he would tell his grandchildren. Exploration and production has always been a business where the risks and the rewards are high, including the danger of layoffs during a downturn. The paper Meehan authored considers how society’s long-term transition to lower-emission energy sources could affect the careers of petroleum engineers. It analyzes what is expected to be a slow-to no-growth industry where digital technology, such as artificial intelligence (AI), will enable fewer engineers to do a lot more. “It is likely that AI-based products and services will greatly leverage petroleum engineers, enabling one engineer to do the work previously requiring many,” the paper said. It added that the changes “suggest that engineering jobs in the future are likely to be smaller in number and radically different from today.” The tone of the paper is sobering, but Meehan said what is ending is not petroleum engineering jobs, just long-standing expectations about working in the industry. He said he met many young engineers during his travels as president who should be able to manage the coming changes. “They are digitally savvy, energetic, and concerned about sustainability issues and ways to lower the carbon intensity of oil and gas production,” he said.

Oil production from heavy oil wells in western Canada jumped after One of those wells is owned by Canadian Natural Resources (CNRL), which reported that production rose 50% (SPE 196187). The gains “have proven the economics of continuing the operation of the downhole electric heat and CNRL will be applying to continue the enhanced oil recovery process,” according to a report to the Alberta Energy Regulator. Still, those heating cables made by Salamander Solutions are a tough sell. It is up against depressed heavy oil prices, the high cost of electricity in some locations, and long memories of heating cables that failed. “I talked to an operator who told me the reservoir performance when the heater lasted was great, but he would never do it again,” said John Karanikas, the chief technology officer for Salamander, who said that none of its cables has gone out in a customer’s well. Older cables required multiple splices to connect 100–200 m sections. If one of those weak points failed, the rest of the line went out like a string of lights after a single bulb fails, said Scott Penny, general manager for Petrospec Engineering, a partner in the business that installs the heating cables. Salamander’s cables can heat a well more than 7,000 ft long without a splice, Karanikas said. The company is working on planning some complicated installations where a splice is required. The company has put a lot of work into more durable ways of connecting cables, which it has patented. Heating cable technology was developed by Shell, which needed electric cables capable of heating rock to 650°F—which required an electric cable that could heat to 1200°F. In comparison, heavy oil is easy. It only needs to reach 300°F. (Oil shale is kerogen-rich rock where extreme heat can extract a lot of oil, which is different that oil in shale, which is in ultratight rock that is released using fracturing.) Shell tested the cables by running them at even higher temperatures, jolting them with extreme power surges, and simulating years of hard use, Karanikas said. The cable passed those tests and worked in the field, but Shell dropped oil shale in favor of more conventional oil and gas options. Salamander was created to market the heating cable technology, with a staff made up of many veterans of the development process. Tough Customers Both tests in the recent paper were in older wells in a heavy oil field. The many wells like those, which are still on primary production, could offer a large market for electric heating. The Salamander heater cable in the CNRL well was installed by Shell, which sold the field to the Canadian company. Shell was looking for a heating alternative to steam that did not require costly casing upgrades to handle steam heat, said Carl Stretch, a Shell engineer who worked on the project.

E&P Notes Pemex Makes 500 Million Barrel Discovery It is being welcomed as the biggest discovery of oil in Mexico in more than 30 years. Mexican state oil company Pemex said that it found a reservoir in the southeastern state of Tabasco that holds more than 500 million BOE. The onshore discovery was made in May at a site called Quesqui after a test well was drilled and seismic data analyzed. The company said that the Quesqui-1 exploratory well is producing 4,500 B/D with the potential to produce 75,000 B/D. Taking part in the announcement was Mexican President Andres Manuel Lopez Obrador, who campaigned on a promise to revitalize Pemex, the world’s most indebted oil company. Colombia Awards 14 Onshore Blocks Colombia’s National Hydrocarbons Agency (ANH) has awarded 14 onshore blocks as part of its second Permanent Area Assignment Process (PPAA) 2019 auction, resulting in at least $512 million in committed investment. Calgary-based Colombia producers Canacol Energy and Parex Resources led all firms by gaining three blocks each, with one more counteroffer from Parex pending review. Canacol’s three blocks are in the Lower and Middle Magdalena Valleys. The company said it expects to begin exploratory work on the blocks in 2020 and aims to drill in 2021 and 2022. It committed to drill five wells total, of which three will come on the VMM-49 block in the Middle Magdalena Valley. Short-Term Headwinds and Fundamental Long-Term Change Will Challenge Oil and Gas Industry in 2020 Uncertainties in many areas remain a challenge to performance and investment in the oil and gas industry, says Deloitte in its 2020 Oil, Gas, and Chemical Industry Outlook. The firm advises companies that balancing coming disruptive forces associated with energy transition and sustainability with day-to-day positioning will be increasingly crucial next year. The report identified three factors affecting the current business outlook. Weakening economic growth in the US, Europe, and China Trade disputes that have expanded beyond Asia to include Europe Political risk, including the US election, the outcome of the Brexit cycle in Europe, and ongoing tensions in Middle East, both between multiple states and non-state actors with different objectives Equinor, Total, Aker Launch Subsea CO 2 Injection R&D Project Subsea CO 2 separation and injection would represent a major step-forward in the effort to turn the dream of a “subsea factory” into a reality. Announced this week, a joint-industry project has been launched to see whether the required technology can be economically developed. The project is being led by Oslo-based engineering firm Aker Solutions along with oil and gas firms Equinor, Total, and Pertamina. Additional support comes from the CO 2 Capture Project which includes BP, Chevron, and Petrobras as members. In a release, Aker said it “has developed new concepts for subsea processing of well streams from CO 2 -flooded oil fields, in which CO 2 -rich gas is separated, compressed and reinjected back into the reservoir.” The hydrocarbon gas can then flow to a topside facility. ADNOC To Boost Oil Production from Giant Bab Field Abu Dhabi National Oil Company (ADNOC) has awarded a $489-million engineering, procurement, and construction (EPC) contract to Greek firm Archirodon Construction Overseas in a project that will sustain long-term crude oil production of 485,000 B/D from the giant onshore Giant Bab Field, 160 km southwest of Abu Dhabi city. The scope of the upgrade project includes development of producing wells, water injection wells, artificial lift wells, well-bays, let-down stations, water injection clusters, and other infrastructure. The contract has a term of 39 months. Led By the Permian, US Flaring and Associated Gas Production Hit New Highs The volume of gas that is flared or vented in the Permian Basin surpassed all previous levels during the third quarter of this year, according to a report from Oslo-based Rystad Energy. The market intelligence firm said Permian operators in Texas and New Mexico are averaging more than 750 MMcfd, up from the estimated 600–650 MMcfd flared or vented in the previous 9 months. A separate report from the US Energy Information Agency (EIA) highlighted that Permian output topped 5.8 Bcf/D of associated gas in 2018—more than half of the basin’s total gas output. Petrobras Starts Production from Pre-Salt Berbigao Field Petrobras has started crude oil and natural gas production from the P-68 floating production, storage, and offloading (FPSO) vessel in the Berbigao field in the pre-salt Santos Basin. The FPSO, located 230 km off Rio de Janeiro state in 2,280 m of water, can process 150,000 B/D of oil, compress 6 million million m 3 of natural gas, store 1.6 million bbl of oil, and accommodate 154 workers. New wells are expected to be connected to the FPSO in the coming year from both the Berbigao field and Sururu field. The project as a whole will consist of 10 production wells and seven injector wells. Oxy Advances Post-Merger Divestment Program Occidental Petroleum has closed on deals totaling $1.7 billion as part of its divestment program following its $38-billion takeover of Anadarko Petroleum, which closed 8 August. Oxy has completed the formation of a strategic partnership with Colombia’s Ecopetrol, announced in July, to develop 97,000 net acres in the Midland Basin of west Texas for $750 million in cash plus $750 million in carried capital. Oxy said the partnership will allow it to accelerate its development plans in the Midland, where it currently has minimal activity.

Editor's column US crude oil production will reach a record level of 12.29 million B/D in 2019, increasing faster than expected both this year and in 2020, according to the latest US Energy Information Administration (EIA) forecast. Output will rise to 13.29 million B/D next year. Similarly, the International Energy Agency predicted last month that US shale oil production will continue to reshape world energy markets, with the US accounting for 85% of the increase in global oil production to 2030. US output will rise to 19 million B/D over the next decade, wresting additional market share from OPEC producers and Russia, according to the agency’s annual World Energy Outlook. But while shale will continue to affect global markets, some believe this predicted rate of growth may be optimistic. There are already signs that producers are curtailing spending and production in the major shale basins as they are under increasing pressure to focus more on capital discipline and returns rather than production growth. In contrast to the EIA and IEA, consultancy IHS Markit sees much slower growth in US shale next year, just a 440,000 B/D increase, with output flat in 2021. “Going from nearly 2 million B/D annual growth in 2018, an all-time global record, to essentially no growth by 2021 makes it pretty clear that this is a new era of moderation for shale producers,” said Raoul LeBlanc, IHS Markit vice president for North American unconventionals. “This is a dramatic shift after several years where annual growth of more than 1 million B/D was the norm.” IHS Markit predicts prices for West Texas Intermediate (WTI) crude to hover in the $50/bbl range and that capital spending will drop by 10% this year, 12% in 2021, and 8% in 2022, from $102 billion in 2019 to $83 billion in 2022. Prices need to be about $65/bbl for producers to be able to both increase production significantly while also satisfying shareholder expectations, it said. In the meantime, producers are focusing more on completing wells than drilling new ones, which is a more economical way of boosting output. There were 7,740 drilled but uncompleted wells in the seven major US shale regions at the end of September, according to the EIA, compared with 8,800 in January. After years of producing all out, pushing US oil and natural gas production to record levels, shale producers are pulling back. Although output has skyrocketed, particularly in places such as the Permian Basin, financial results have not. Mergers and bankruptcy filings are common, and investors have become reluctant to lend capital. Natural gas companies in particular are hurting, and they are promising more capital discipline and lower production going forward. During third-quarter earnings calls, Chesapeake Energy, EQT, Callon Petroleum, Cimarex, and Diamondback Energy all signaled flat to lower spending and production. Chesapeake’s CEO had to re assure investors of the company’s financial health a week after the company said in a third-quarter earnings filing that it had “substantial doubt” of its ability to continue as a going concern. “I don’t think OPEC has to worry that much more about US•shale growth long term,” Pioneer Natural Resources Scott Sheffield told investors last month.

E&P Notes ExxonMobil, Hess To Start Production Off Guyana By Year End The first phase of oil production from the Stabroek Block offshore Guyana will start up before year end, ahead of the previously scheduled first-quarter 2020 date, partner Hess said in its third-quarter earnings release. First oil from the 120,000-B/D Liza Destiny floating production, storage, and offloading vessel (FPSO), which arrived on the block in late August, is targeted for December. It is expected to take 3 months before the FPSO ramps up to full capacity. The development consists of four subsea drill centers and 17 wells, of which eight are production wells, six water injection wells, and three gas injection wells. • Hess To Tie Back Deepwater US Gulf Oil Discovery Hess will tie back its Esox-1 oil discovery in the deepwater US Gulf of Mexico to its Tubular Bells facilities and begin production in the first quarter of 2020. Drilled in 1405 m of water, the Esox-1 well encountered 58 m of high-quality oil-bearing Miocene reservoirs, the company said. Esox-1 is located on Mississippi Canyon Block No. 726 and is•10 km east of the Tubular Bells production facilities. • EIA: US Gulf Oil Output To Continue Record Pace US crude oil production in the Gulf of Mexico will continue to set production records in each of 2019 and 2020, according to projections from the US Energy Information Administration (EIA). Based on expected production levels at new and existing fields, annual US gulf oil output will increase to 1.9 million•b/d in 2019 and 2 million B/D in 2020. The estimates include shut-ins related to Hurricane Barry in July and adjustments for additional hurricane-related shut-ins this year and next. • BP Discovers Gas with Orca-1 Well Offshore Mauritania BP’s operated Orca-1 exploration well in the BirAllah area off Mauritania encountered 36 m of net gas pay in excellent quality reservoirs while targeting a previously untested Albian play, partner Kosmos Energy said. The well, drilled in 2,510 m of water to a TMD of 5,266 m, also extended the Cenomanian play fairway by confirming 11 m of net gas pay in a down-structure position relative to the original Marsouin-1 discovery well, which was drilled on the crest of the anticline. The Orca-1 location, 7.5 km from the crest of the anticline, proved both the structural and stratigraphic trap of the Orca prospect, which has an estimated mean gas initially in place of 13 Tcf. • Eni, EGPC Fast-Track Gulf of Suez Appraisal Well Eni and the Egyptian General Petroleum Corporation (EGPC) will fast-track production of an appraisal well on their Abu Rudeis Sidri development lease in the Gulf of Suez off Egypt. The Sidri 36 appraisal well confirmed the downdip westward extension of the Sidri 23 discovery announced last July by the Italian major. Sidri 36 encountered a 200-m hydrocarbon column in the clastic sequences of the Nubia formation. • ADNOC, Russia Advance Oil and Gas Partnerships Abu Dhabi National Oil Company (ADNOC) signed separate agreements involving oil and gas industry collaboration with Russian oil and gas giants Lukoil and Gazprom Neft and the Russian Energy Agency (REA). In two pacts, ADNOC awarded a 5% stake in the Ghasha Concession to Lukoil, and the companies along with the Russian Direct Investment Fund agreed to explore future cooperation on the concession, which is a gas, oil, and gas condensate development targeting nine shallow-water fields in the Arabian Gulf west of Abu Dhabi. • C&J Energy, Keane To Become NexTier Oilfield Solutions The merger of C&J Energy Services and Keane Group closed 31 October, at which point the combined firm became known•as NexTier Oilfield Solutions. Shareholders of both companies approved the deal on 22 October. The new well completion and production services company will rank just behind Halliburton and Schlumberger in terms of total US hydraulic fracturing horsepower. • ONGC Makes Discoveries in Colombia, Brazil ONGC Videsh, the international subsidiary of India’s state-owned Oil and Natural Gas Corporation (ONGC), has made oil and gas discoveries in South America. In Colombia’s onshore Llanos Basin, the ONGC Videsh-operated Well Sol-1 on the CPO-5 block encountered 8 m of oil-bearing sands at a depth of 2852 m. The well confirmed the extent of oil pay on the southern portion of the block following the company’s Mariposa-1 and Indico-1 discoveries in 2017–2018. Those wells are currently on production. ONGC Videsh holds a 70% interest in•the CPO-5 block. • Chevron, Repsol Awarded Most Blocks in Brazil’s 16th Round Ten companies from nine countries were awarded whole or partial stakes in 12 blocks as part of Brazil’s 16th Round, the country’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP)•reported. Signature bonuses in the auction, which involved the offshore Campos and Santos Basins, totaled $2.17 billion. Chevron and Spain’s Repsol secured the most blocks with four each; Qatar Petroleum subsidiary QPI Brasil and Malaysia’s Petronas each gained three blocks; Shell, BP, and Wintershall DEA each added two blocks; and Total, ExxonMobil, and Petrobras were awarded one block each.

President's column I cannot believe that a year has passed since I was inaugurated as SPE president in Dallas last September. My term has passed at the speed of light as I have traveled all over the world meeting our members and representing SPE at conferences and other events. I believe what I enjoyed the most was visiting with our student members in university chapters, engaging with our industry’s future leaders. I saw the pride and hope in their eyes. Our industry, and our world, face some significant challenges in the decades ahead. I saw in their faces the willingness to embrace and solve those challenges. Many are ready to call themselves Citizen Engineers, and bring best-in-class environmental and social practices to bear, even as they strive to meet growing world energy demand. According to the latest BP Energy Outlook, over the next 20 years, world reliance on oil and gas in the overall energy mix will decline only slightly in percentage terms, and will actually rise in total volume supplied. By 2040, meeting projections for world energy demand will require a 6% in-crease in oil production and a 33% increase in natural gas production. In both cases, this increase is after compensating for natural declines of 3–5% per year in conventional fields and much higher declines in unconventional resources. Being able to find, develop, produce, and deliver that level of resources to power world economies will be a significant undertaking. That challenge is coupled with the growing environmental and social challenges of our planet. World population will increase by 1.7 billion in the next 20 years, with almost half that growth in Africa, which currently has the highest levels of energy poverty. According to the Energy Outlook, the world will need to double current gross domestic product by 2040 to support these new inhabitants. The biggest environmental challenge is rising CO 2 emissions. World opinion holds fossil fuels responsible, and that is putting increasing pressure on our license to operate. We must respond—not by denying or debating our role, but by demonstrating leadership in addressing the problem. I am encouraged by the efforts I see happening across our industry to address CO 2 emissions, with substantial investments, initiatives, and solid plans being•made.• During my talks around the world, I highlighted 10 game changers where our industry can help to arrest the CO 2 emission increase. Reducing gas flaring. Our industry has successfully reduced the amount of flared gas by 15% while oil production increased by 33%. Flared gas has value—capturing the associated natural gas and diverting it to power generation or petrochemicals acquires that value as well as significantly reducing methane and CO 2 emissions. I see huge opportunities for more investment in countries currently flaring their associated gas so they can generate electric power for their citizens and industries.

Natural gas flared in just two major US shale plays exceeded the amount of gas consumed last year in Colombia and Israel. The prolific waste from the Permian and the Bakken (Figs. 1 and 2) is a side effect of rising oil production in plays where gas growth is so strong pipeline construction cannot keep up. Flaring is a glaring reminder of the realities of the never-ending rush to drill that is driving down the cost of oil and gas around the globe. These oil-producing wells also produce more gas than processing plants and pipelines can move to market. Pipelines and refineries have recognized that ultralight oil in the Permian is fundamentally different from West Texas Intermediate (WTI), with a make-up that puts it somewhere between oil and gas•liquids. As those wells age, oil production falls as the output shifts to gas. And the cost of sustaining production for the vast majority of producers has consistently exceeded the cash generated by these wells (Fig.• 3). The gap between capital expenditures and revenues was “a staggering $4.7•billion” during the first quarter of 2019, according to a study by Alisa Lukash, a senior analyst on Rystad Energy’s North American shale team, who described it as a “tremendous overspend.” Both the US Energy Information Administration (EIA) and Rystad have raised outlooks that already predicted strong US oil growth. Flaring growth and overspending have accompanied a rebound in growth in the Permian and Bakken, which are the flaring leaders by far in the US. More than half of the total comes from the Permian, which has surpassed the Bakken by more than tripling the volume of gas burned per day since early 2017. The severity of the problem, though, is more acute in the Bakken. While Rystad said about 5% of the Permian gas is flared, in the Bakken, 19% of the gas is flared, according to the oil and gas division of the North Dakota Industrial Commission. The Permian produces far more gas but has the advantage of being close to growing markets for it—chemical plants, export pipelines to Mexico, and natural gas liquefaction facilities—while North Dakota is a distant option for Midwestern markets well supplied by other plays. Limited pipeline capacity means those shippers without contracts ensuring they can move their gas are paid little or less than nothing—prices at Waha gas hub in west Texas repeatedly sank into negative territory over the winter, and pipeline shortages will linger until a big new pipeline goes into service. Oil pipeline construction also has lagged supply growth in the Bakken. Trains and trucks can ship oil, but that is a costly option. North Dakota oil regulators reported that Bakken prices hovered around $50/bbl early this year when the benchmark US oil grade was about $10/bbl higher.

Editor's column With the shale industry still awash in red ink, and oil prices falling, it may take more consolidation to try to bring some financial stability to the sector. The financing strategy of the shale sector has always differed from onshore conventional oil business models. The small and medium-sized independents that have dominated shale have operated with much higher levels of debt and, since the beginning of the unconventional rise, have operated with negative free cash flow. Although production has skyrocketed, profitability has not, and Wall Street investors have grown tired of financing a largely unprofitable piece of the oil and gas business. The International Energy Agency (IEA) predicted last year that the shale industry would finally achieve positive free cash flow this year as oil prices rebounded and new pipelines relieved bottlenecks that had depressed prices. But the sharp downturn in oil prices in the fourth quarter and the recent decline to near $50/bbl (WTI) has not helped. When the shale boom was taking off between 2010 and 2014, high oil prices led to huge financial backing. Investment quadruped during that period, according to the IEA, as oil production increased from 0.44 million B/D to 3.6 million B/D, the fastest oil growth since the advent of Saudi Arabia’s giant oil fields in the 1960s. When oil prices tanked beginning in 2014, shale firms, along with the rest of the industry, switched to sharply cutting costs and trying to instill capital discipline. It was too much for some. More than a hundred shale firms filed for bankruptcy during 2015–16. Banks became more reluctant to lend money, even after oil prices began to recover, leading to a wave of lending from private equity firms. Production from the sector continued to defy odds, but profitability was still not in sight. BP’s most recent bellwether Statistical Review of World Energy, released in June, noted that US oil and gas production growth accelerated in 2018 at another record pace. The production growth “exceeded any other country’s annual increase in our 50-year history” of publishing the review, said BP Chief Economist Dale Spencer. “Indeed, the US achieved a unique double-first last year, recording the single largest-ever annual increase by any country in both oil and gas production. In case there was any doubt, the US shale revolution is alive and kicking,” he said. Since 2012, US oil production, including natural gas liquids, has grown by more than 7 million B/D, “broadly equivalent to Saudi Arabia’s crude oil exports, an astonishing increase which has trans-formed both the structure of the US economy and global market dynamics,” he added. But how long this revolution can continue without solid economic footing is unclear. One trend under way is consolidation. Two years ago, many independents began selling off assets so they could continue drilling. Today, many are pursuing assets sales, drilling partnerships, and other alternative financing strategies, according to an article in The Wall Street Journal. A new wave of company consolidations and buyouts by larger firms may have started. Chevron attempted to buy Anadarko and its sizable presence in the Permian Basin but was beat out by Occidental. Although Shell and other majors have indicated that, while interested, current selling prices for some companies appear too steep, the Anadarko deal could be the first of many that attempts to bring some stability to the shale sector and increases the presence of larger, more diversified firms.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 193650, “Augmented-Artificial-Intelligence Solutions for Heavy-Oil Reservoirs: Innovative Work Flows That Build From Smart Analytics, Machine Learning, and Expert-Based Systems,” by David Castineira, Xiang Zhai, and Hamed Darabi, Quantum Reservoir Impact Group, prepared for the 2018 SPE International Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 10–12 December. The paper has not been peer reviewed. Recently, many heavy-oil fields have seen exponentially higher volumes of data made available as a result of omnipresent connectivity. Existing data platforms have focused traditionally on solving the problem of data storage and access. The more-complex problem of true knowledge discovery and systematic value creation from the massive amount of data is less frequently addressed. The authors of this paper propose a novel work flow for the problem of building intelligent data analytics in heavy-oil fields. Introduction Optimal reservoir management for heavy-oil reservoirs requires systematic solutions that combine both engineering ability and advanced analytics. The authors believe that this requirement is addressed by what they call augmented artificial intelligence (AAI), a process inspired by the intelligence-amplification concept in which machine learning and human expertise are combined to improve solutions derived by systems that learn without any type of input from engineers or geoscientists. Practical deployment of AAI will involve automated work flows that use solid technical expertise and proven processes to transform field data into more-effective reservoir-management solutions. Even with rapid data-preprocessing solutions in place, developing an optimal reservoir-management framework for heavy-oil assets is inherently complex. Identifying key recovery obstacles (KROs) and field-development plans (FDPs) typically takes many months, involving a large team of experts and the construction of sophisticated full-field simulation models. The recommendation is that automated work flows and AAI solutions are combined to identify those KROs rapidly and prepare robust FDPs that increase production and optimize current operations. Perhaps the less-intuitive step in developing systematic solutions for heavy-oil fields is the process of developing a quantitative reservoir diagnostic framework. This process must build from big-data analytics platforms and an array of analytical, numerical, and empirical models combined to deliver a catalog of KROs affecting field performance. To this end, the entire historical set of well, field, and reservoir data must be processed and input into this diagnostics platform. Once the KROs are understood, the next step is to translate the diagnostics into detailed action plans in the field that can generate production, reserves, or capital-efficiency improvements. This paper aims to offer an alternative approach to traditional work flows that identify recovery obstacles and development opportunities in heavy-oil fields by labor-intensive solutions. In contrast, the authors propose a systematic framework that provides three key advantages: Execution time is fast, and an initial opportunity inventory can be generated. The user can choose from multiple algorithms and methods to customize the technology to unique field/reservoir complexities. The core algorithms are data-driven, integrate multidisciplinary data sets, and leave little room for the biases of the user, which allows for a consistent and repeatable analysis.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28716, “Campos Basin Technologies Yard: 40 Years of Lessons Learned,” by M. Roberto, A.B. Coutinho, and A.R. Dos Santos, Petrobras, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–3 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Over the last 40 years, the Campos Basin has been a major stage for technology development to push offshore oil and gas production to water depths (WDs) never before experienced. This paper presents a retrospective of the most-significant technologies developed and deployed in the Campos Basin for more than 80 production systems in more than 30 oil- and gas-field developments; a few of these milestones are described in this synopsis. Introduction The discovery of oil in the Campos Basin in 1974 occurred in the context of the 1973 world oil crisis and its effects on geopolitics and the global economy. In addition to the challenges associated with this period, a need existed to increase oil production while reducing costs, leading to a fast-track approach. The development of the Garoupa field, followed by the Pargo, Badejo, Namorado, Enchova, Bonito, and Pampo fields, revealed huge oil-production potential, minimizing Brazil’s need to import petroleum. The development and application of new technologies, such as early production systems (EPS), horizontal wells, tree standardization, flexible pipes, and subsea processing and boosting, allowed the necessary cost reduction and risk mitigation. Now, most of these technologies are consolidated and are used in new Brazilian discoveries, particularly in presalt areas. To speed the development of these technologies, a deep- and ultradeepwater technology program, the Technological Development Program for Deep water Production Systems (PROCAP), was initiated in 1986. PROCAP and its four versions—PROCAP 1000 (1000-m well depth), PROCAP 2000, PROCAP 3000, and PROCAP Future Vision, have since supported the development of Campos Basin technologies and the exploration of new frontiers. Technology Development Many technologies have been developed in the Campos Basin during the last 40 years in order to support the production, developing, revitalization, life extension, and decommissioning of its fields. The Campos Basin development has become successful because of a strong partnership between the operator and suppliers, academia, research centers, and other operators. Despite the challenges faced during the last 40 years, the Campos Basin served as an excellent laboratory in which technologies, methodologies, internal programs, human-resource initiatives, suppliers and subsuppliers, university resources, and engineering and spinoff companies were developed to achieve and sustain the high production of these fields. 1971 to 1974: First Exploratory Wells Drilled and First Discoveries. The first exploratory well in the Campos Basin, named 1-RJS-1, was drilled in 1971 with a jackup-type rig at a WD of 49 m, which resulted in a dry well with no indications of hydrocarbons. In the following years, additional exploratory wells were drilled in WDs of greater than 60 m. The first indications of hydrocarbons were noticed in 1973 in another exploratory well, although it had no production potential. In fact, seven dry wells were drilled since the beginning of the well-exploration campaign.

E&P Notes CNOOC’s “Major Find” In North Sea Is Biggest In 11 Years Trent Jacobs, JPT Digital Editor The Chinese National Offshore Oil Corporation (CNOOC) discovered a gas and condensate reservoir at the state-owned company’s Glengorm prospect in the UK North Sea. The resource, located 118 miles east of Aberdeen, is estimated to hold close to 250 million bbl BOE. CNOOC tapped the reservoir in a water depth of 282 ft with a jackup rig. Total depth of the exploration well was just over 16,500 ft and gas and condensate pay zones were found with a thickness of 123 ft. The company had previously tried and failed to drill two prospect wells in 2017. Xie Yuhong, executive vice president of CNOOC, said the “Glengorm discovery demonstrates the great exploration potential” for the offshore block and that the company is “looking forward to further appraisal.” CNOOC is the operator of the field with a 50% interest. French supermajor Total owns a 25% stake in the field and Euroil holds the remaining 25%. Chesapeake Teams with Analytics Firm to Improve Asset Performance Matt Zborowski, Technology Writer Chesapeake Energy is partnering with RS Energy Group to improve operational efficiency and capital discipline by employing advanced analytics and machine learning. RS Energy is a Calgary-based energy research firm founded in 1998 covering more than 150 operators in the major North American and international oil and gas regions, including the US shale plays. It provides technical analysis of basins, including completions and production, as well as asset evaluations for operators considering acreage additions. All of this is done within the context of shifting capital markets. Chesapeake announced the pact fresh off its $4-billion merger with WildHorse Resource Development, which bolstered its position in the Eagle Ford Shale of South Texas. The Oklahoma City-based independent has overhauled its portfolio in recent years and now is focused on just a few major US basins, increasing its companywide share of oil production, and reducing debt. Noble Energy Touts Output Gains, Potential from “Row Development” Concept Matt Zborowski, Technology Writer “Row development” is in full swing on Noble Energy’s operated acreage in Colorado’s DJ Basin, and now the company is beginning to apply the approach to its Delaware Basin acreage in West Texas. The first completed row in Noble’s 75,000-acre Mustang project in the DJ Basin produced 26,000 BOE/D, of which 60% was oil, during fourth quarter 2018, the independent reported in its year-end earnings call. The row consists of 31 wells. “We expect that momentum to continue into 2019,” said Brent Smolik, Noble president and chief operating officer. Bolstered in part by row development, the firm’s overall DJ oil and gas output increased 10% during the quarter and 15% for the year. EIA Adds New Plays to Shale Gas, Tight Oil Reports Stephen Whitfield, Senior Staff Writer The US Energy Information Administration (EIA) has added new play production data to its shale gas and tight oil reports. Last December, US shale and tight plays produced approximately 65 Bcf/D of natural gas and 7 million B/D of crude oil, accounting for 70% and 60% of US production in those areas, respectively. These totals represent a significant jump in the last 10 years: shale gas and tight oil accounted for 16% of total US gas production and approximately 12% of US total crude oil production, according to EIA statistics. EIA updated its production volume estimates to include seven additional shale gas and tight oil plays, increasing the share of shale gas by 9% and tight oil by 8% compared with previously estimated shale production volumes. The change captures increasing production from new, emerging plays as well as from older plays that had previously been in decline, but are now rebounding because of advancements in horizontal drilling and hydraulic fracturing. Devon Pulls Up Its Roots, Goes All In on US Oil Stephen Rassenfoss, JPT Emerging Technology Senior Editor Devon Energy will be shedding its holdings in the Barnett and the Canadian oil sands as part of a program to shrink the company to focus on four US unconventional oil plays. The program announced along with earnings is the last step in a series of asset sales to create a “New Devon,” which also promises to reduce annual costs by $780 million by 2021, with most of that done by the end of this year. The “sustainable cost reductions” will target expenses in field operations, drilling, and completions. It did not specifically mention job reductions, but the list of cost-saving steps includes “better aligning personnel with the go-forward business.” Brazil’s Lula Field a Step Closer to Producing 1 Million B/D Petrobras, alongside partners Shell and Galp, has launched production from the seventh Lula field floating production, storage, and offloading (FPSO) vessel, bringing the consortium a step closer to reaching 1 million B/D of oil from the prolific Lula hub offshore Brazil. Hydrocarbons are flowing to the P-67 FPSO as part of the Lula North deepwater project in the pre-salt Santos Basin. The vessel, which has a capacity of 150,000 B/D of oil and 6 million cu m/day of natural gas, sits in 2130 m of water on the BM-S-11 concession 260 km off Rio de Janeiro state. P-67 will be connected to nine production wells and multiple injection wells. Oil will be offloaded to lifting vessels and gas will be sent through pre-salt gas pipelines.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190695, “Simulations of In-Situ Upgrading Process: Interpretation of Laboratory Experiments and Study of Field-Scale Test,” by A. Perez-Perez, SPE, M. Mujica, and I. Bogdanov, SPE, Computational Hydrocarbon Laboratory for Optimized Energy Efficiency, and A. Brisset, SPE, and O. Garnier, SPE, Total, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. In-situ upgrading (IU) is a promising method of improved viscous- and heavy-oil recovery. The IU process involves a reservoir being exposed to temperatures greater than 300°C long enough to promote a series of chemical reactions. In this work, the authors developed a numerical model of IU on the basis of laboratory experiences and validated results, applying the model to an IU test published in the literature. Simulation results for the cores submitted have shown that oil production and oil-sample quality were well-predicted by the model. Introduction In this paper, results of a previously published experiment and those of an unpublished experiment (Experiment B) are modeled and discussed. To accomplish this, an in-house code is developed for coupling the kinetic model with the thermodynamic description, a process detailed in the complete paper. This code was able to represent both the reaction dynamics of bitumen-fraction decomposition and the phase distribution and production of pseudocomponents. The resulting model was used to simulate an IU field-scale test (using data from Shell’s Viking pilot). Experimental Simulation A 2D homogeneous radial model was used to simulate two IU experiments. Elemental gridblock size was 5 mm in both directions. The model size was 5×30 cells (Experiment A) and 5×138 cells (Experiment B). A total of 30 pseudocomponents was provided in the simulation model. A sensitivity analysis was performed to identify the effect of some parameters in the IU model on the basis of experimental conditions in the experiments. This analysis was focused on less-certain properties related to the core and physical properties of oil pseudocomponents. Experimental and Simulation Results. In the process of model development and adaptation, more effort has been dedicated to specify the thermodynamic model than the kinetic model. The final model is capable of successfully predicting liquid production at various test scales and conditions. To explain the mismatch observed between simulation and experimental results of solid generation during IU, the authors performed estimations of solid mass that would be generated under the IU conditions of both experiments in a closed system. The resulting amount of generated solids is the highest possible because the initial hydrocarbons were all retained inside a core. The estimated amount of pyrobitumen for Experiment A was 0.022 kg. This value is still lower than that reported for laboratory conditions (0.024 kg). With regard to Experiment B, taking into account that 35% of the original oil was evacuated by thermal expansion of fluids, the estimated mass of pyrobitumen was approximately 0.070 kg (for closed volume). This value is significantly lower than that reported by the laboratory for this experiment (0.090 kg). The most probable reason is a natural difference in the physicochemical conditions for measurements in kinetic tests and IU experiments.

Technology Focus Are You There Yet? For the optimal completion system, does “there” mean customization, standardization, or component modularity? Does it mean maximum reservoir contact or maximum surface contact? More or fewer clusters? Does it mean a completion that uses many compartments or fewer compartments? Are modular components part of the solution? In practice, optimality could include any or all of these. Business as Usual? More than ever, the industry needs reliable, flexible, cost-effective completion solutions. Increasingly, completion experts must think creatively to improve the performance and longevity of a completion system so that it achieves economic targets with reliability. A recent analysis using an Eagle Ford data set investigated the relationship between rock brittleness and proppant bridging. The conclusion revealed that conventional thinking on cluster spacing and shot density must be challenged to improve injectivity and to realize the potential of the fracturing program. Simulation Fracturing design is in its third generation in the Bakken and is being driven by analysis that combines legacy production data, legacy zonal spacing, and offset-well data. One author is reporting increases in oil production in the range of 300 to 400%, while achieving lower water cut. Given the steep decline curves typical of these wells, this work cannot be ignored. Design, Process Risk Assessment The use of risk assessment in completion design is growing; it is no longer just for offshore applications. Those who acknowledge this are (correctly) advocating for its inclusion in the earliest stage of the completion process. Some authors observe that operational risks and consequences must be considered in the planning phase, rather than the execution phase, for maximum benefit. An example is the use of risk assessment for completion installation in wells with tortuous paths. It is probably not news that the drilling of wells with very tortuous paths is increasing. However, rather than hope for the best during installation, it is now possible to model and simulate beyond caliper data and dogleg severity to understand what must be done to place the completion bottomhole assembly at depth in good working condition. Force Multipliers How are results such as higher oil production and lower completion cost being achieved in an industry with fewer human resources and shorter project schedules? Multidisciplinary project teams are one force multiplier. Such teams enable early understanding of formation, drilling, and completion interactions. This knowledge leads to earlier optimization of the completion system, when it is cost-effective to make the necessary changes. Subject-matter-expert input at this stage of the completion design process eliminates or reduces risk. Standardization and modularity in component and system design are two other multipliers. Modularity offers the potential to simplify system design, and standardization offers the potential for operational flexibility. Although these are an aid to the operator, both can lead to improved delivery schedules from suppliers. Summary My conclusion is that we are on a good path but much work remains. To achieve better than good completion design, we must accelerate our use of all the tools and processes available—traditional and nontraditional. To get “there,” what also is required is the application of more simulation, increased emphasis on extracting the value from large legacy data sets, and the use of risk management in the planning phase. The result will be truly optimized completion design and improved project economics. Recommended additional reading at OnePetro: www.onepetro.org. SPE 191767 Redefining Bakken Completions: A Tailored Approach to Stimulation by Kyle Trainor, NP Resources, et al. SPE 191390 Completion and Stimulation Design of the First Offshore Acid- Fractured Multistage Dual-Lateral Well by R. Oberhofer, Packers Plus Energy Services, et al.